ONEOK Partners Announces Higher Third-quarter 2011 Financial Results; Increases 2011 Earnings Guidance by More Than 15 Percent

TULSA, Okla., Nov. 1, 2011 /PRNewswire/ -- ONEOK Partners, L.P. (NYSE: OKS) today announced third-quarter 2011 earnings of 84 cents per unit, compared with 54 cents per unit for the third quarter 2010.  Net income attributable to ONEOK Partners was $209.7 million for the third quarter 2011, compared with $141.5 million for the same period in 2010.

Nine-month 2011 net income attributable to ONEOK Partners was $531.7 million, or $2.09 per unit, compared with $330.4 million, or $1.20 per unit, for the nine-month period a year earlier.  

The partnership also increased its 2011 net income guidance by more than 15 percent to a range of $740 million to $770 million, compared with the previous guidance range of $630 million to $660 million, reflecting higher anticipated earnings in the partnership's natural gas liquids segment.

The partnership's distributable cash flow (DCF) is now expected to be in the range of $850 million to $880 million, compared with the previous guidance range of $735 million to $765 million.

"Our natural gas liquids segment turned in exceptional third-quarter results, primarily as a result of strong natural gas liquids price differentials," said John W. Gibson, chairman, president and chief executive officer of ONEOK Partners.  "We also experienced higher natural gas liquids volumes gathered and fractionated, as a result of the investments we've made in infrastructure projects since 2006.

"We continue to benefit from our integrated natural gas liquids operations that allow us to capture additional margins from favorable natural gas liquids price differentials as more transportation and fractionation capacity became available for optimization activities," he added.

"The natural gas gathering and processing segment benefited from higher commodity prices and higher natural gas volumes processed in the Williston Basin where the partnership is investing in new plants and infrastructure to increase its gathering and processing capacity," said Gibson.  

In the third quarter 2011, earnings before interest, taxes, depreciation and amortization (EBITDA) were $312.6 million, a 32-percent increase compared with $236.7 million in the third quarter 2010.  Year-to-date 2011 EBITDA was $842.1 million, a 34-percent increase compared with $630.4 million in the same period last year.  

DCF for the third quarter 2011 was $233.4 million, a 50-percent increase compared with $156.0 million in the third quarter 2010.  DCF for the first nine months of 2011 was $624.7 million, a 50-percent increase compared with $417.8 million in the same period last year.

Operating income for the third quarter 2011 was $242.4 million, a 51-percent increase compared with $160.5 million for the third quarter 2010.  For the first nine months of 2011, operating income was $622.0 million, a 46-percent increase compared with $426.6 million in the prior-year period.  

The increases in operating income for both the three- and nine-month 2011 periods reflect favorable natural gas liquids (NGL) price differentials; increased NGL fractionation and transportation capacity available for optimization activities; higher NGL volumes gathered and fractionated; contract renegotiations; and higher isomerization margins in the natural gas liquids segment.

The natural gas gathering and processing segment benefited from higher net realized commodity prices, higher natural gas volumes processed and favorable changes in contract terms, offset partially by lower natural gas volumes gathered primarily in the Powder River Basin.

Third-quarter and nine-month 2011 results reflect the deconsolidation of Overland Pass Pipeline Company and the gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company in September 2010.  These results are included in equity earnings from investments in the natural gas liquids segment.  Additionally, the natural gas pipelines segment realized lower transportation margins due to narrower natural gas price location differentials that primarily impacted contracted capacity on Midwestern Gas Transmission.

Operating costs were $106.3 million in the third quarter of 2011, compared with $97.8 million for the same period last year.  Operating costs for the nine-month 2011 period were $328.6 million, compared with $292.1 million in the same period last year.  The increases for both the three- and nine-month 2011 periods were due to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs; higher property taxes; and higher expenses for materials and outside services associated primarily with scheduled maintenance at the partnership's NGL fractionation and storage facilities.

Equity earnings from investments were $32.0 million in the third quarter 2011, compared with $29.4 million in the same period in 2010.  Nine-month 2011 equity earnings from investments were $93.7 million, compared with $71.2 million in the same period last year.  The increase for the nine-month 2011 period was due primarily to the partnership's 50-percent interest in Overland Pass Pipeline included in equity earnings from investments that became effective September 2010 and increased contracted capacity on Northern Border Pipeline, in which the partnership owns a 50-percent interest.

Capital expenditures were $252.2 million in the third quarter 2011, compared with $104.1 million in the same period in 2010.  Nine-month 2011 capital expenditures were $662.4 million, compared with $202.8 million in the same period last year.  This increase was due to growth projects in the natural gas gathering and processing and natural gas liquids segments.

> View earnings tables

THIRD-QUARTER 2011 SUMMARY:

• Operating income of $242.4 million, compared with $160.5 million in the third quarter 2010;
• Natural gas gathering and processing segment operating income of $51.8 million, compared with $38.2 million in the third quarter 2010;
• Natural gas pipelines segment operating income of $34.0 million, compared with $39.0 million in the third quarter 2010;
• Natural gas liquids segment operating income of $157.1 million, compared with $83.2 million in the third quarter 2010;
• Equity earnings from investments of $32.0 million, compared with $29.4 million in the third quarter 2010;
• Capital expenditures of $252.2 million, compared with $104.1 million in the third quarter 2010;
• Having $127.9 million of cash and cash equivalents and no commercial paper or borrowings outstanding as of Sept. 30, 2011, under the partnership's $1.2 billion revolving credit facility;
• Completing a two-for-one split of the partnership's common units and Class B units on July 12, 2011, with the distribution of one unit for each unit outstanding.  As a result, the partnership now has 130,827,354 common units and 72,988,252 Class B units outstanding, and its minimum quarterly distribution and target distribution levels have been adjusted proportionately;
• Entering into in August a new $1.2 billion, five-year senior unsecured revolving credit facility that expires in August 2016; and
• On a split-adjusted basis, increasing the quarterly cash distribution to 59.5 cents per unit from 58.5 cents per unit, payable on Nov. 14, 2011, to unitholders of record as of Nov. 7, 2011, resulting in an annualized cash distribution of $2.38 per unit.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported third-quarter 2011 operating income of $51.8 million, compared with $38.2 million for the third quarter 2010.  

Third-quarter 2011 results reflect an $11.6 million increase from higher net realized NGL and condensate prices; a $6.2 million increase from higher natural gas volumes processed in the Williston Basin, offset partially by lower volumes in Kansas due to natural production declines; and a $3.0 million increase due to favorable changes in contract terms.  These increases were offset partially by a $2.2 million decrease due to a favorable contract settlement in the third quarter 2010; and a $2.0 million decrease from lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity in the Powder River Basin in Wyoming.

Operating income for the nine-month 2011 period was $138.3 million, compared with $114.1 million in the same period last year.  

Nine-month 2011 results reflect a $26.7 million increase from higher net realized commodity prices; an $11.8 million increase due to favorable changes in contract terms; and a $9.3 million increase from higher natural gas volumes processed in the Williston Basin resulting from increased drilling activity, which more than offset the impact of reduced drilling activity in certain parts of western Oklahoma and Kansas, and weather-related outages in the first quarter 2011.  

These increases were offset partially by a $6.1 million decrease from lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity in the Powder River Basin in Wyoming.

Operating costs in the third quarter 2011 were $35.0 million, compared with $34.1 million in the same period last year.  Nine-month 2011 operating costs were $109.6 million, compared with $98.5 million in the same period last year.  The increases in operating costs for both the three- and nine-month 2011 periods were due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs, and higher property taxes.

Key Statistics: More detailed information is listed in the tables.

• Natural gas gathered totaled 1,044 billion British thermal units per day (BBtu/d) in the third quarter 2011, relatively unchanged compared with the same period last year due to continued production declines in the Powder River Basin in Wyoming and certain parts of Kansas, offset partially by increased drilling activity in the Williston Basin; and up 2 percent compared with the second quarter 2011;
• Natural gas processed totaled 723 BBtu/d in the third quarter 2011, up 8 percent compared with the same period last year due to increased drilling activity in the Williston Basin, offset partially by natural production declines in Kansas; and up 6 percent compared with the second quarter 2011;
• The realized composite NGL net sales price was $1.09 per gallon in the third quarter 2011, up 25 percent compared with the same period last year; and unchanged compared with the second quarter 2011;
• The realized condensate net sales price was $87.89 per barrel in the third quarter 2011, up 35 percent compared with the same period last year; and up 7 percent compared with the second quarter 2011;
• The realized residue gas net sales price was $5.25 per million British thermal units (MMBtu) in the third quarter 2011, down 6 percent compared with the same period last year; and down 9 percent compared with the second quarter 2011; and
• The realized gross processing spread was $8.17 per MMBtu in the third quarter 2011, up 44 percent compared with the same period last year; and down 3 percent compared with the second quarter 2011.

NGL shrink, plant fuel and condensate shrink discussed in the table below refer to the Btus that are removed from natural gas through the gathering and processing operation; it does not include volumes from the partnership's equity investments.  The following table contains operating information for the periods indicated:

The natural gas gathering and processing segment is exposed to commodity-price risk as a result of receiving commodities in exchange for services.  The following tables provide hedging information in the natural gas gathering and processing segment for the periods indicated:

The partnership's natural gas gathering and processing segment currently estimates that a 1 cent per gallon change in the composite price of NGLs would change annual net margin by approximately $1.5 million.  A $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.3 million.  Also, a 10 cent per MMBtu change in the price of natural gas would change annual net margin by approximately $2.0 million.  All of these sensitivities exclude the effects of hedging and assume normal operating conditions.

Natural Gas Pipelines Segment

The natural gas pipelines segment reported third-quarter 2011 operating income of $34.0 million, compared with $39.0 million for the third quarter 2010.  

Third-quarter 2011 results reflect a $3.7 million decrease from lower transportation margins, due primarily to narrower natural gas price location differentials that reduced contracted transportation capacity on Midwestern Gas Transmission and reduced interruptible transportation volumes across its pipelines; and a $1.2 million decrease from lower realized prices on its retained fuel position.

Operating income for the nine months 2011 was $100.6 million, compared with $122.1 million in the same period in 2010.  

Nine-month 2011 results reflect a $9.6 million decrease from lower transportation margins, primarily due to narrower natural gas price location differentials that reduced contracted transportation capacity on Midwestern Gas Transmission and reduced interruptible transportation volumes across its pipelines; and a $4.5 million decrease from lower realized prices on its retained fuel position.  These decreases were offset partially by an increase of $2.3 million due to higher natural gas storage margins.

Operating costs were $24.4 million in the third quarter 2011, compared with $24.8 million in the same period last year.  Nine-month 2011 operating costs were $79.1 million, compared with $71.3 million in the same period last year.  The increase in operating costs for the nine-month 2011 period was due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs, higher outside services costs related to pipeline integrity and maintenance projects, and higher property taxes.

Equity earnings from investments were $19.8 million in the third quarter 2011, compared with $21.3 million in the same period in 2010.  The decrease was due to lower transportation rates on Northern Border Pipeline, in which the partnership owns a 50-percent interest.

Nine-month 2011 equity earnings from investments were $57.4 million, compared with $48.9 million in the same period last year.  The nine-month 2011 increase was due to higher contracted capacity on Northern Border Pipeline due to wider natural gas price differentials between the markets it serves.  Substantially all of Northern Border Pipeline's capacity is contracted through October 2012.

Key Statistics: More detailed information is listed in the tables.

• Natural gas transportation capacity contracted totaled 5,132 thousand dekatherms per day in the third quarter 2011, down 6 percent compared with the same period last year due primarily to lower contracted capacity on Midwestern Gas Transmission resulting from narrower natural gas price location differentials; and down 3 percent compared with the second quarter 2011;
• Natural gas transportation capacity subscribed was 79 percent in the third quarter 2011 compared with 84 percent subscribed for the same period last year; and down from 82 percent in the second quarter 2011; and
• The average natural gas price in the Mid-Continent region was $4.02 per MMBtu in the third quarter 2011, up 2 percent compared with the same period last year; and down 4 percent compared with the second quarter 2011.

Natural Gas Liquids Segment

The natural gas liquids segment reported third-quarter 2011 operating income of $157.1 million, compared with $83.2 million for the third quarter 2010.  

Third-quarter 2011 results reflect:

• An $89.4 million increase due to favorable NGL price differentials and increased NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets;
• A $7.9 million increase from higher NGL volumes gathered and fractionated, and favorable contract renegotiations associated with its exchange-services activities;
• A $7.3 million increase in isomerization margins from wider price differentials between normal butane and iso-butane, and higher isomerization volumes; and
• A $3.1 million increase due to higher storage margins as a result of favorable contract renegotiations.

These increases were offset partially by a $16.3 million gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company recorded in the third quarter 2010 and a $10.2 million decrease, compared with the same period last year, resulting from the deconsolidation of Overland Pass Pipeline in September 2010.

Operating costs were $47.6 million in the third quarter 2011, compared with $39.5 million in the third quarter 2010 due primarily to higher expenses for materials and outside services associated with scheduled maintenance at its fractionator and storage facilities, higher property taxes and higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs.  

Operating income for the nine months 2011 was $383.5 million, compared with $191.9 million in 2010.  

Nine-month 2011 results reflect:

• A $207.4 million increase as a result of favorable NGL price differentials and increased NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets;
• A $29.6 million increase from higher NGL volumes gathered and fractionated, and favorable contract renegotiations associated with its exchange-services activities;
• A $12.8 million increase in isomerization margins from wider price differentials between normal butane and iso-butane, and higher isomerization volumes; and
• A $9.2 million increase due to higher storage margins as a result of favorable contract renegotiations.

These increases were offset partially by a $42.8 million decrease, compared with the same period last year, resulting from the deconsolidation of Overland Pass Pipeline in September 2010 and a $16.3 million gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company recorded in the third quarter 2010.

Nine-month 2011 operating costs were $141.1 million, compared with $126.2 million in the same period last year.  This increase was due primarily to higher labor and employee-related costs associated with incentive and benefit plans, which includes equity-based compensation costs; higher expenses for materials and outside services associated with scheduled maintenance at its fractionator and storage facilities; and higher property taxes.  These increases were offset partially by the deconsolidation of Overland Pass Pipeline in September 2010.

Depreciation and amortization expense was $16.6 million for the third quarter 2011, compared with $17.4 million for the same period in 2010.  Nine-month 2011 depreciation and amortization expense was $47.6 million, compared with $53.7 million in the same period last year.  These decreases were due primarily to the deconsolidation of Overland Pass Pipeline in September 2010.

Equity earnings from investments were $4.3 million in the third quarter 2011, compared with $0.7 million in the same period in 2010.  Nine-month 2011 equity earnings from investments were $14.3 million, compared with $1.7 million in the same period last year.  This increase was due to the deconsolidation of Overland Pass Pipeline in September 2010 that is included in equity earnings from investments.

Key Statistics: More detailed information is listed in the tables.

• NGLs fractionated totaled 529 thousand barrels per day (MBbl/d) in the third quarter 2011, up 6 percent compared with the same period last year due primarily to increased production through existing supply connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions; and down 2 percent compared with the second quarter 2011;
• NGLs transported on gathering lines totaled 443 MBbl/d in the third quarter 2011, up 15 percent compared with the same period last year, after adjusting for the September 2010 deconsolidation of Overland Pass Pipeline, due primarily to increased production through existing supply connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions; and up 3 percent compared with the second quarter 2011;
• NGLs transported on distribution lines totaled 457 MBbl/d in the third quarter 2011, relatively unchanged compared with the same period last year ; and down 1 percent compared with the second quarter 2011; and
• The Conway-to-Mont Belvieu average price differential for ethane, based on Oil Price Information Service (OPIS) pricing, was 27 cents per gallon in the third quarter 2011, up 170 percent compared with the same period last year; and up 35 percent compared with the second quarter 2011.

GROWTH ACTIVITIES:

During 2010 and in 2011, the partnership announced approximately $2.7 billion to $3.3 billion in growth projects include:

• Approximately $910 million to $1.2 billion for natural gas liquids projects that have approximately two-thirds of the available capacity committed and include:
  • The construction of a 570-plus-mile, 16-inch NGL pipeline, the Sterling III Pipeline,  expected to cost approximately $610 million to $810 million and is expected to be completed in late 2013, to transport either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast with the initial capacity to transport 193,000 bpd and the ability to expand to 250,000 bpd;
  • The reconfiguration of its existing Sterling I and II NGL distribution pipelines to transport either unfractionated NGLs or NGL purity products; and
  • The construction of a new 75,000 bpd natural gas liquids fractionator, MB-2, at Mont Belvieu, Texas, that is expected to cost approximately $300 million to $390 million and is expected to be completed in mid-2013;
• Approximately $350 million to $415 million to construct the Garden Creek plant, a new 100 million cubic feet per day (MMcf/d) natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which is expected to be in service by the end of 2011, and related expansions; and for new well connections, expansions and upgrades to the existing natural gas gathering system infrastructure;
• Approximately $300 million to $355 million by the end of 2012 to construct the Stateline I plant, a new 100 MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which is expected to be in service in the third quarter of 2012, and related NGL infrastructure;  expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
• Approximately $260 million to $305 million by the end of 2014 to construct the Stateline II plant, a new 100 MMcf/d natural gas processing facility in the Bakken Shale in the Williston Basin in North Dakota, which is expected to be in service in the first half of 2013; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
• Approximately $595 million to $730 million of natural gas liquids projects that have 100-percent volume commitments and include:
  • The construction of a 525- to 615-mile NGL pipeline to transport unfractionated NGLs produced from the Bakken Shale in the Williston Basin to the Overland Pass Pipeline, a 760-mile NGL pipeline extending from southern Wyoming to Conway, Kan., which is expected to be in service during the first half of 2013, with the initial capacity to transport 60,000 bpd and can be expanded to 110,000 bpd with additional pump stations;
  • A 60,000 bpd capacity expansion on ONEOK Partners' 50-percent interest in the Overland Pass Pipeline to transport the additional unfractionated NGL volumes from the new Bakken Pipeline; and
  • A 60,000 bpd expansion of the partnership's fractionation capacity at Bushton, Kan., which is expected to be in service during the first half of 2013, to accommodate the additional NGL volumes;  
• Approximately $180 million to $240 million to construct more than 230 miles of 10- and 12-inch diameter NGL pipelines that will expand the partnership's existing Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash areas, which, when completed, is expected to add approximately 75,000 to 80,000 bpd of raw, unfractionated NGLs to the partnership's existing NGL gathering systems in the Mid-Continent and the Arbuckle Pipeline. These investments are expected to be completed in the first half of 2012 and will connect three new third-party natural gas processing facilities with total expected capacity of 510 MMcf/d and three existing third-party natural gas processing facilities that are being expanded; and include the installation of additional pump stations on the Arbuckle Pipeline to increase its capacity to 240,000 bpd; and
• Approximately $36 million for the installation of seven additional pump stations along the existing Sterling I NGL distribution pipeline, increasing its capacity by 15,000 bpd that will be supplied by Mid-Continent NGL infrastructure.  Installation began last year, and all of the pump stations are expected to be in service by the end of November 2011.

2011 EARNINGS GUIDANCE INCREASED

ONEOK Partners' 2011 net income is expected to be in the range of $740 million to $770 million, compared with its previous range of $630 million to $660 million.  The updated guidance reflects higher anticipated earnings in the partnership's natural gas liquids segment.

Estimates for the partnership's 2011 DCF were updated and are expected to be in the range of $850 million to $880 million, compared with its previous range of $735 million to $765 million.

Additional information is available in the guidance tables on the ONEOK Partners website.

The midpoint for ONEOK Partners' 2011 operating income guidance has been updated to $870 million, compared with its previous guidance of $752 million.

The midpoint of the natural gas gathering and processing segment's 2011 operating income guidance has been updated to $177 million, compared with its previous guidance of $180 million, reflecting higher operating costs.

The average unhedged prices assumed for the fourth quarter 2011 are $85 per barrel for New York Mercantile Exchange (NYMEX) crude oil, $3.94 per MMBtu for NYMEX natural gas and $1.24 per gallon for composite natural gas liquids.

The midpoint of the natural gas pipelines segment's 2011 operating income guidance has been updated to $133 million, compared with its previous guidance of $141 million. These lower expected earnings are primarily the result of narrower natural gas price location differentials that have reduced contracted transportation capacity on Midwestern Gas Transmission and reduced demand for interruptible transportation services across the segment's pipelines, and higher operating costs.

The midpoint of the natural gas liquids segment's 2011 operating income guidance has been updated to $560 million, compared with its previous guidance of $431 million. Updated guidance reflects favorable NGL price differentials. For the fourth quarter 2011, the Conway-to-Mont Belvieu OPIS average ethane price differential is expected to be 41 cents.

The midpoint for equity earnings from investments guidance has been increased to $126 million, compared with previous guidance of $123 million. This increase reflects higher anticipated earnings from Northern Border Pipeline, in which ONEOK Partners owns a 50-percent interest.

Capital expenditures for 2011 are expected to be approximately $1.2 billion, comprised of approximately $1.1 billion in growth capital and $97 million in maintenance capital.

EARNINGS CONFERENCE CALL AND WEBCAST:

ONEOK Partners and ONEOK management will conduct a joint conference call on Wednesday, Nov. 2, 2011, at 11 a.m. Eastern Daylight Time (10 a.m. Central Daylight Time).  The call will also be carried live on ONEOK Partners' and ONEOK's websites.

To participate in the telephone conference call, dial 888-329-8889, pass code 4184520, or log on to www.oneokpartners.com or www.oneok.com.

If you are unable to participate in the conference call or the webcast, the replay will be available on ONEOK Partners' website, www.oneokpartners.com, and ONEOK's website, www.oneok.com, for 30 days.  A recording will be available by phone for seven days.  The playback call may be accessed at 888-203-1112 pass code 4184520.

LINK TO EARNINGS TABLES:

http://www.oneokpartners.com/Investor/FinancialInformation/~/media/ONEOKPartners/EarningsTables/OKS_Q3_2011_Earnings_zvB3e1S.ashx

NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) FINANCIAL MEASURES

ONEOK Partners has disclosed in this news release anticipated EBITDA and DCF levels that are non-GAAP financial measures.  EBITDA and DCF are used as measures of the partnership's financial performance.  EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, income taxes and allowance for equity funds used during construction.  DCF is defined as EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, adjusted for distributions received and certain other items.

The partnership believes the non-GAAP financial measures described above are useful to investors because these measurements are used by many companies in its industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate the financial performance of the partnership and to compare the financial performance of the partnership with the performance of other publicly traded partnerships within its industry.

EBITDA and DCF should not be considered alternatives to net income, earnings per unit or any other measure of financial performance presented in accordance with GAAP.

These non-GAAP financial measures exclude some, but not all, items that affect net income. Additionally, these calculations may not be comparable with similarly titled measures of other companies.  Furthermore, these non-GAAP measures should not be viewed as indicative of the actual amount of cash that is available for distributions or that is planned to be distributed for a given period nor do they equate to available cash as defined in the partnership agreement.

ONEOK Partners, L.P. (NYSE: OKS) is one of the largest publicly traded master limited partnerships, and is a leader in the gathering, processing, storage and transportation of natural gas in the U.S. and owns one of the nation's premier natural gas liquids (NGL) systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.  Its general partner is a wholly owned subsidiary of ONEOK, Inc. (NYSE: OKE), a diversified energy company, which owns 42.8 percent of the overall partnership interest.  ONEOK is one of the largest natural gas distributors in the United States, and its energy services operation focuses primarily on marketing natural gas and related services throughout the U.S. 

For more information, visit the website at www.oneokpartners.com.

For the latest news about ONEOK Partners, follow us on Twitter @ONEOKPartners.

Some of the statements contained and incorporated in this news release are forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended.  The forward-looking statements relate to our anticipated financial performance, liquidity, management's plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters.  We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.  The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this news release identified by words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "should," "goal," "forecast," "guidance," "could," "may," "continue," "might," "potential," "scheduled" and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this news release.  Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements.  Those factors may affect our operations, markets, products, services and prices.  In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

• the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;
• competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;
• the capital intensive nature of our businesses;
• the profitability of assets or businesses acquired or constructed by us;
• our ability to make cost-saving changes in operations;
• risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
• the uncertainty of estimates, including accruals and costs of environmental remediation;
• the timing and extent of changes in energy commodity prices;
• the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs;
• the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers' desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
• difficulties or delays experienced by trucks or pipelines in delivering products to or from our terminals or pipelines;
• changes in demand for the use of natural gas because of market conditions caused by concerns about global warming;
• conflicts of interest between us, our general partner, ONEOK Partners GP, and related parties of ONEOK Partners GP;
• the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control;
• our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;
• actions by rating agencies concerning the credit ratings of us or the parent of our general partner;
• the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas regulatory authorities or any other local, state or federal regulatory body, including the Federal Energy Regulatory Commission (FERC), the National Transportation Safety Board (NTSB), the Pipeline and Hazardous Materials Safety Administration (PHMSA), the Environmental Protection Agency (EPA) and the Commodity Futures Trading Commission (CFTC);
• our ability to access capital at competitive rates or on terms acceptable to us;
• risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling;
• the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;
• the impact and outcome of pending and future litigation;
• the ability to market pipeline capacity on favorable terms, including the effects of:
  • future demand for and prices of natural gas and NGLs;
  • competitive conditions in the overall energy market;
  • availability of supplies of Canadian and United States natural gas; and
  • availability of additional storage capacity;
• performance of contractual obligations by our customers, service providers, contractors and shippers;
• the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
• our ability to acquire all necessary permits, consents and other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;
• the mechanical integrity of facilities operated;
• demand for our services in the proximity of our facilities;
• our ability to control operating costs;
• acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers' or shippers' facilities;
• economic climate and growth in the geographic areas in which we do business;
• the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
• the impact of recently issued and future accounting updates and other changes in accounting policies;
• the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;
• the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
• risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
• the impact of uncontracted capacity in our assets being greater or less than expected;
• the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
• the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
• the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
• the impact of potential impairment charges;
• the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
• our ability to control construction costs and completion schedules of our pipelines and other projects; and
• the risk factors listed in the reports we have filed and may file with the Securities and Exchange Commission (SEC), which are incorporated by reference.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements.  Other factors could also have material adverse effects on our future results.  These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in the Annual Report.  All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors.  Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

SOURCE ONEOK Partners, L.P.

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